In developing oil and gas resources, it is often desirable to drill long, extended-reach (“ER”) wells from a fixed drilling center such as a platform, pad, or subsea template. The ER wells allow distal parts of a field or distal reservoirs to be developed without having to construct a new wellbore or move the drilling center. The use of ER wells typically results in less cost, and may result in capture of oil and gas that would otherwise be uneconomic. The ER wells also have a number of other advantages, including less environmental impact and the ability to use existing infrastructure. In offshore environments, dry tree ER wells may also facilitate less costly workovers in comparison to subsea wells. The world record for reach (sometimes called throw) is currently about 11 kilometers (km), and this record was set in 1999.
In constructing ER wells, there often arises the need to run a tubular conduit, often referred to as a casing or liner, into the well. The tubular or conduit may also be referred to as a tubular pipe, tubing, string, or coiled tubing. The terms tubular, conduit or tubular conduit are equivalent and can be used interchangeably. In vertical or low-angle wells, the gravitational force acting on the casing or liner is usually sufficient to propel the pipe into the well. However, for horizontal or high-angle wells, because of the drag created by axial friction between the pipe and the wellbore, it may be impossible to run the casing or liner into the well using current practice. This is particularly true for wells with a high ratio of reach to total vertical depth (“TVD”). For such wells, the driving gravitational force pushing the casing or liner into the well may be less than the axial drag force resisting the motion of the casing or liner. The drag arises principally from the normal force between the casing and the wellbore wall and a friction coefficient that converts the normal force into an axial drag force. In high-angle wells, the normal force is high because a significant component of the weight of the pipe acts normal to the wellbore wall.
To overcome the drag acting on well tubulars being inserted into high-angle or ER wells, the oil and gas industry has devised a number of means of reducing the friction coefficient or reducing the normal force. For example, additives sometimes referred to as lubricants, can be placed in the drilling fluid to reduce the friction coefficient. In addition, casing/liner centralizers containing roller elements, sometimes referred to as roller centralizers, have been used to reduce the friction coefficient. However, none of the methods to reduce the friction coefficient can reduce the coefficient to zero. Thus, there is a limit on the length of casing or liner that can be run in high-angle wells using the friction reduction technology.
Another method to install pipe in ER wells is to simultaneously rotate the pipe while running it into the well. This method changes the direction of the velocity vector between the points of contact of the pipe and the wellbore wall. A non-axial velocity vector changes the direction of the frictional force so that less of the force acts in the axial direction opposing the running of the pipe. However, rotation is often limited by the torque capacity of the rig and/or the pipe connections. Also, since there is always some axial component of the frictional force, rotation cannot completely eliminate the axial drag. Thus, there is a limit on the length of casing or liner that can be run in a high-angle well using rotation.
Another method, often called casing or liner floatation, is sometimes used to facilitate installation of a casing or liner in a high-angle well. This method involves directly reducing the normal force acting between the casing or liner and the wellbore wall. Normally, as a casing or liner string is run into a wellbore, the casing or liner is filled with a liquid wherein the liquid often has a similar density as the external drilling fluid. The purpose of filling the casing or liner with the liquid is to help reduce the risk that the casing or liner will collapse as it is run deeper into the well. The casing/liner floatation method typically involves running a portion of the casing or liner that will line the high-angle part of the well empty or containing a lightweight fluid. The fluid being lightweight as compared to the external wellbore fluid. The internal lightweight fluid is typically air. The internal lightweight fluid reduces the effective weight per foot of the casing or liner and thereby reduces the normal force. Although this method is commonly called “floating” the casing or liner or casing or liner “floatation,” the current practice is not to cause the casing or liner to become neutrally buoyant. See, for example, U.S. Pat. Nos. 5,117,915 and 5,181,571.
Neutral buoyancy is a state where a solid object submerged or partially submerged in a fluid experiences no net vertical force because the vertical component of the fluid-pressure-induced buoyant forces on the object exactly offset the vertical gravitational force or the weight, acting on the object. Most casing or liners are made from steel. It is typically not possible to cause the casing or liner to become neutrally buoyant by simply reducing the density of the internal fluid or even running the string with a gas inside. The reason for this is due to the high-density of steel with a specific gravity of approximately 7.8 and the geometry of casing or liner that is placed in the high-angle portion of the well. Therefore, there still typically exists a normal force between the casing and the wellbore when utilizing conventional technology since the casing or liner is not neutrally buoyant. This normal force creates a limit to the length of pipe that can be run in a high-angle well even using conventional casing floatation.
It is noted that some authors have suggested that neutral buoyancy can be achieved by adjusting the physical dimensions of the casing or liner. For example, in U.S. Pat. No. 5,181,571, it is suggested that the diameter and cross sectional [wall] thickness (and associated weight) of the pipe string can be adjusted to equal the weight of the displaced bore fluid. In most applications, this likely requires increasing the diameter of the casing or liner to increase the buoyant force acting on the pipe and/or decreasing the wall thickness to reduce the air weight per foot of the pipe. The reference cited does not specifically teach adjusting the external fluid to provide neutral buoyancy, but rather teaches adjusting the weight and size of the pipe string. Increasing the diameter of the casing or liner is often not feasible because the casing or liner has to fit through a previous casing string and into the borehole that has been drilled. Increasing the diameter and/or decreasing the wall thickness may also cause problems with satisfying other design requirements related to the collapse and burst resistance of the pipe string.
The casing/liner floatation method typically involves placing fluids having multiple densities inside the casing or liner. This is because it is desirable to have a low-density fluid in the casing or liner run into the high-angle portion of the well and a high-density fluid above a fixed plug inside the casing or liner in the low-angle portion of the well. The high-density fluid facilitates driving the string into the wellbore by increasing the gravitational force acting on the string. In using casing or liner floatation, typically the distal part of the string is filled with a lightweight fluid (or run empty) as the string is run into the wellbore. The float equipment (containing a check valve) prevents the heavier external mud from entering the string as it is run. After insertion of a desired amount of tubular filled with lightweight fluid into the wellbore, a second or proximal plug is placed within the tubular to trap the lightweight fluid in place. The length of lightweight-filled tubular can be several thousand meters (several thousand feet) depending upon the specific geometry of the borehole. The lightweight fluid reduces the effective weight per foot of the tubular in the high-angle part of the wellbore. The tubulars above the location of the proximal plug are used as an insertion string that is filled with a fluid typically more dense than the light fluid of the lower section. These tubulars can be additional casing or liner or pipe including, drill pipe. An illustrative example of this method is described in detail in U.S. Pat. No. 5,117,915.
While these existing methods can be effective in installing tubulars in some high-angle wellbores, there are limitations associated with the current practice. Specifically, since none of the current methods completely eliminate the axial friction force acting on the casing or liner in the high-angle portion of the well, there is a limit to the length of casing or liner that can be run into a high-angle well. This is typical for wells in which the reach to total vertical depth ratio is large with, for example, a ratio larger than 3. In such wells, the driving force to push the casing or liner into the well is small compared to the axial friction force opposing the motion of the casing or liner. Computer calculations indicate that, using conventional technology, the longest length of 69.94 kilogram/meter (kg/in) (47 pound/foot (lb/ft)) 0.24448 m (9⅝-inch) casing that can be run in a well with a TVD of 2000 meter (m) is about 11 km.
Another limitation of current practice is that the current casing floatation technique may increase the risk of collapsing the casing or liner. For instance, if the light fluid is a gas, for example, air, then by the conventional flotation method the pressure in the buoyed interval is essentially atmospheric. Further, gases at near-atmospheric pressure are very compressible. As such, the inserted tubular's resistance to collapse is essentially provided by the tubular alone. There is essentially no internal pressure to help counteract the external pressure that works to crush the tubular. If the fluid is a compressible liquid (such as oil or diesel), the pressure in the buoyed portion of the tubular will be above atmospheric pressure, but still below the in-wellbore pressure. As such, the inserted tubular's net collapse resistance is less than it would be if the tubular remained open and was filled with the same mud as is in the wellbore annulus. The net collapse resistance includes both the mechanical strength of the tubular wall and the internal pressure in the tubular. If the wall thickness is increased to improve collapse resistance, the drag on the tubular will also increase due to the greater weight per unit length.
Accordingly, there is a need for an improved tubular insertion methodology that allows an increase in the length of casing or liner that can be run into a high-angle well and reduce risk of tubular collapse. This invention satisfies that need.